Hydrocarbon Wells and Methods for Monitoring Fracture Morphology of a Fracture that Exends from a Wellbore of the Hydrocarbon Wells

ABSTRACT

Hydrocarbon wells and methods for monitoring fracture morphology of a fracture that extends from a wellbore of the hydrocarbon wells are disclosed herein. The hydrocarbon wells include a wellbore, a fracture that extends from the wellbore, and an electromagnetic contrast material positioned within the fracture. The hydrocarbon wells also include a downhole electromagnetic transmitter, which is configured to direct an electromagnetic probe signal incident upon the electromagnetic contrast material, and a downhole electromagnetic receiver, which is configured to receive an electromagnetic resultant signal from the electromagnetic contrast material. The methods include flowing an electromagnetic contrast material into a fracture and generating an electromagnetic probe signal. The methods also include modifying the electromagnetic probe signal with the electromagnetic contrast material to generate an electromagnetic resultant signal. The methods further include receiving the electromagnetic resultant signal and determining the morphology of the fracture.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the benefit of U.S. Provisional Application62/904,150, filed Sep. 23, 2019, the disclosure of which is herebyincorporated by reference in its entirety.

FIELD OF THE INVENTION

The present disclosure relates generally to hydrocarbon wells and/or tomethods for monitoring fracture morphology of a fracture that extendsfrom a wellbore of the hydrocarbon wells.

BACKGROUND OF THE INVENTION

During formation and/or completion of hydrocarbon wells, fractureoperations may be utilized to fracture a subsurface region within whichthe hydrocarbon well extends, such as to increase a fluid permeabilityof the subsurface region. While mechanisms for forming fractures withina subsurface region are well-established, the shape, size, and/or extentof the formed fractures generally is not known. Thus, there exists aneed for hydrocarbon wells that include interrogation devices positionedwithin a fracture and/or for methods of monitoring at least one propertyof a fracture.

SUMMARY OF THE INVENTION

Hydrocarbon wells and methods for monitoring fracture morphology of afracture that extends from a wellbore of the hydrocarbon wells aredisclosed herein. The hydrocarbon wells include a wellbore that mayextend within a subsurface region, a fracture that extends from thewellbore and/or within the subsurface region, and an electromagneticcontrast material that may be positioned within the fracture. Thehydrocarbon wells also include a downhole electromagnetic transmitter,which may be configured to direct an electromagnetic probe signalincident upon the electromagnetic contrast material, and a downholeelectromagnetic receiver, which may be configured to receive anelectromagnetic resultant signal from the electromagnetic contrastmaterial.

The methods include flowing an electromagnetic contrast material from awellbore and/or into a fracture. The methods also include generating anelectromagnetic probe signal. The electromagnetic probe signal may begenerated with a downhole electromagnetic transmitter and/or thegenerating may include generating such that the electromagnetic probesignal is incident upon the electromagnetic contrast material. Themethods further include modifying the electromagnetic probe signal withthe electromagnetic contrast material and/or to generate anelectromagnetic resultant signal. The methods also include receiving theelectromagnetic resultant signal. The receiving may include receivingwith a downhole electromagnetic receiver. The methods further includedetermining the morphology of the fracture. The determining may bebased, at least in part, on the electromagnetic resultant signal.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic illustration of examples of a hydrocarbon wellaccording to the present disclosure.

FIG. 2 is a schematic illustration of examples of electromagneticcontrast material that may be included in and/or utilized withhydrocarbon wells and/or methods, according to the present disclosure.

FIG. 3 is another schematic illustration of examples of electromagneticcontrast material that may be included in and/or utilized withhydrocarbon wells and/or methods, according to the present disclosure.

FIG. 4 is a flowchart depicting examples of methods of monitoring amorphology of a fracture that extends from a wellbore of a hydrocarbonwell, according to the present disclosure.

DETAILED DESCRIPTION OF THE INVENTION

FIGS. 1-4 provide examples of hydrocarbon wells 18, of electromagneticcontrast material 40, and/or of methods 100, according to the presentdisclosure. Elements that serve a similar, or at least substantiallysimilar, purpose are labeled with like numbers in each of FIGS. 1-4, andthese elements may not be discussed in detail herein with reference toeach of FIGS. 1-4. Similarly, all elements may not be labeled in each ofFIGS. 1-4, but reference numerals associated therewith may be utilizedherein for consistency. Elements, components, and/or features that arediscussed herein with reference to one or more of FIGS. 1-4 may beincluded in and/or utilized with any of FIGS. 1-4 without departing fromthe scope of the present disclosure. In general, elements that arelikely to be included in a particular embodiment are illustrated insolid lines, while elements that are optional are illustrated in dashedlines. However, elements that are shown in solid lines may not beessential and, in some embodiments, may be omitted without departingfrom the scope of the present disclosure.

FIG. 1 is a schematic illustration of examples of a hydrocarbon well 18according to the present disclosure. Hydrocarbon wells 18 include awellbore 20, which may extend within a subsurface region 12, and afracture 30, which may extend from the wellbore and/or within thesubsurface region. Wellbore 20 also may be referred to herein asextending between a surface region 10 and a subterranean formation 14 ofsubsurface region 12 and/or as extending within the subterraneanformation. Hydrocarbon wells 18 also include an electromagnetic contrastmaterial 40, which may be positioned within fracture 30. Hydrocarbonwells 18 further include a downhole electromagnetic transmitter 50 and adownhole electromagnetic receiver 60.

During operation of hydrocarbon wells 18, and as discussed in moredetail herein, downhole electromagnetic transmitter 50 may be configuredto direct an electromagnetic probe signal 52 incident upon and/or intoelectromagnetic contact with electromagnetic contrast material 40.Responsive to receipt of electromagnetic probe signal 52,electromagnetic contrast material 40 may modify the electromagneticprobe signal to produce and/or generate an electromagnetic resultantsignal 62. Downhole electromagnetic receiver 60 may be configured toreceive electromagnetic resultant signal 62 from electromagneticcontrast material 40. A morphology of fracture 30 then may be monitored,determined, estimated, and/or quantified based, at least in part, onelectromagnetic probe signal 52, electromagnetic resultant signal 62,and/or a comparison between the electromagnetic probe signal and theelectromagnetic resultant signal.

In some examples of hydrocarbon wells 18, wellbore 20 may be a firstwellbore 21, such as illustrated in solid lines in FIG. 1. It is withinthe scope of the present disclosure, however, that hydrocarbon wells 18also may include a second wellbore 22, such as illustrated in dashedlines in FIG. 1. When hydrocarbon well 18 includes first wellbore 21 andsecond wellbore 22, first wellbore 21 may be adjacent second wellbore22, may be parallel to second wellbore 22, and/or may be at leastsubstantially parallel to second wellbore 22.

In these examples, downhole electromagnetic transmitter 50 may bepositioned within one of first wellbore 21 and second wellbore 22, anddownhole electromagnetic receiver 60 may be positioned in the other offirst wellbore 21 and second wellbore 22. Stated another way, onewellbore 20 may include downhole electromagnetic transmitter 50, and theother wellbore 20 may include downhole electromagnetic receiver 60.

In these examples, downhole electromagnetic transmitter 50 may beconfigured to direct, or to transmit, electromagnetic probe signal 52 inand/or within a plane 54 that extends between first wellbore 21 andsecond wellbore 22. Additionally or alternatively, downholeelectromagnetic receiver 60 may be configured to receive electromagneticresultant signal 62 from plane 54. Stated another way, electromagneticprobe signal 52 may be incident upon electromagnetic contrast material40 within plane 54 and/or electromagnetic resultant signal 62 may begenerated within plane 54. Stated yet another way, and in this example,hydrocarbon well 18 may be configured to measure fracture 30 withinplane 54 and/or to determine an extent of fracture 30 within plane 54.

In these examples, electromagnetic contrast material 40 may beconfigured to modify electromagnetic probe signal 52. For example,electromagnetic contrast material 40 may be configured to modify aphase, to modify an amplitude, and/or to modify a frequency ofelectromagnetic probe signal 52 to produce and/or generateelectromagnetic resultant signal 62. Stated another way, a phase, anamplitude, and/or a frequency of electromagnetic resultant signal 62 maydiffer from a phase, an amplitude, and/or a frequency of a correspondingelectromagnetic probe signal 52, which was modified to generate theelectromagnetic resultant signal. This difference in phase, amplitude,and/or frequency may be caused by, or due to, interactions, orelectromagnetic interactions, between the electromagnetic probe signaland electromagnetic contrast material 40.

An example of electromagnetic contrast material 40 that may be utilizedto produce the phase, amplitude, and/or frequency shift may include anelectrically conductive material. Examples of electrically conductivematerial that may be utilized as electromagnetic contrast material 40include an electrically conductive particulate, a metal, an electricallyconductive polymer, an electrically conductive fluid, a ferrofluid,and/or a magnetorheological fluid.

In some examples, downhole electromagnetic transmitter 50 and downholeelectromagnetic receiver 60 both may be positioned within wellbore 20,within the same wellbore 20, and/or within a single wellbore 20, such asthe leftmost wellbore 20 that is illustrated in FIG. 1. In theseexamples, downhole electromagnetic transmitter 50 may be configured totransmit electromagnetic probe signal 52 away from wellbore 20, and/orelectromagnetic contrast material may be configured to cause at least aportion of electromagnetic resultant signal 62 to be directed backtoward wellbore 20 and/or incident upon downhole electromagneticreceiver 60. As an example, electromagnetic contrast material 40 may beconfigured to reflect at least the portion of electromagnetic probesignal 52 toward wellbore 20 as electromagnetic resultant signal 62. Asanother example, electromagnetic contrast material 40 may be configuredto scatter at least a portion of electromagnetic probe signal 52 towardwellbore 20 as electromagnetic resultant signal 62.

Examples of electromagnetic contrast material 40 that may be utilized toreflect and/or to scatter electromagnetic probe signal 52 to produceand/or generate electromagnetic resultant signal 62 include anelectromagnetically shielding material, an electromagnetically shieldingliquid, an electromagnetically shielding particulate material, amaterial that scatters electromagnetic radiation, a liquid that scatterselectromagnetic radiation, and/or a particulate that scatterselectromagnetic radiation. More specific examples of materials thatreflect and/or scatter electromagnetic probe signal 52 and which may beutilized as electromagnetic contrast material 40 include graphite,exfoliated graphite, carbon, carbon black, and/or coke.

In some examples, hydrocarbon wells 18 may be configured to transmit adata stream 72, which may be indicative of the morphology of fracture30, from downhole electromagnetic receiver 60 and/or to surface region10. As an example, and as illustrated in dashed lines in FIG. 1,hydrocarbon wells 18 may include a data transmission structure 70, whichmay be configured to transmit data stream 72. An example of datatransmission structure 70 includes an electrical conductor and/or anoptical fiber 74, which may extend between the downhole electromagneticreceiver and the surface region and/or may be configured to convey anelectrical data stream 72 and/or an optical data stream 72. Anotherexample of data transmission structure 70 includes a downhole wirelesscommunication network 76. Downhole wireless communication network 76,when present, may convey data stream 72 via any suitable wirelesssignal, examples of which include an acoustic signal, an optical signal,and/or an electromagnetic signal.

As also illustrated in dashed lines in FIG. 1, downhole electromagneticreceiver 60 may include a data transmitter 64. Data transmitter 64, whenpresent, may be configured to generate data stream 72 and/or to transmitdata stream 72 to surface region 10 via data transmission structure 70.

In some examples, and as illustrated in dashed lines in FIG. 1,hydrocarbon wells 18 may include a casing string 28. Casing string 28may extend within wellbore 20 and/or may define a casing conduit 29. Inthese examples, hydrocarbon wells 18 also may include a fracture fluidsupply system 80, which may be configured to provide a fracture fluidstream 82 to casing conduit 29, such as to pressurize the casingconduit. In addition, hydrocarbon wells 18 may include a perforation gun90. Perforation gun 90, when present, may be positioned within casingconduit 29 and/or may be configured to selectively perforate casingstring 28, such as to permit and/or facilitate formation of fractures 30within subsurface region 12.

In these examples, electromagnetic contrast material 40 may be entrainedwithin fracture fluid stream 82. Additionally or alternatively,electromagnetic contrast material 40, downhole electromagnetictransmitter 50, and/or downhole electromagnetic receiver 60 may beutilized to detect and/or monitor formation of fractures 30. This mayinclude real-time, or at least substantially real-time, detection and/ormonitoring of a size, extent, and/or volume of fractures 30 duringand/or after formation of fractures 30.

In these examples, fracture fluid stream 82 also may include a proppantmaterial 48, which may be utilized to prop, or to hold open, fracture 30subsequent to formation thereof. Proppant material 48 may be separateand/or distinct from electromagnetic contrast material 40. Additionallyor alternatively, at least a fraction of electromagnetic contrastmaterial 40 may function as and/or may be proppant 48. As an example,and as discussed in more detail herein, electromagnetic contrastmaterial 40 may include an electrically conductive coating material thatmay coat and/or cover a proppant material, or a conventional proppantmaterial.

Downhole electromagnetic transmitter 50 may include any suitablestructure that may be adapted, configured, designed, and/or constructedto generate electromagnetic probe signal 52, to direct theelectromagnetic probe signal away from wellbore 20, and/or to direct theelectromagnetic probe signal incident upon electromagnetic contrastmaterial 40. As an example, downhole electromagnetic transmitter 50 mayinclude and/or be a ground penetrating radar transmitter. In someexamples, electromagnetic probe signal 52 may include and/or be apolarized electromagnetic probe signal. In some examples,electromagnetic probe signal 52 may have a probe signal frequency in thehigh frequency (HF), very high frequency (VHF), ultra high frequency(UHF), and/or super high frequency (SHF) ranges. More specific examplesof the probe signal frequency include frequencies of at least 1kilohertz (KHz), at least 10 KHz, at least 50 KHz, at least 100 KHz, atleast 500 KHz, at least 1 megahertz (MHz), at least 5 MHz, at least 10MHz, at least 25 MHz, at least 50 MHz, at least 100 MHz, at least 250MHz, at least 500 MHz, at least 1 gigahertz (GHz), at most 5 GHz, atmost 2.5 GHz, at most 1 GHz, at most 500 MHz, at most 250 MHz, and/or atmost 100 MHz.

FIGS. 2-3 are schematic illustrations of examples of electromagneticcontrast material 40 that may be included in and/or utilized withhydrocarbon wells 18 of FIG. 1 and/or methods 100 of FIG. 4, accordingto the present disclosure. As discussed, electromagnetic contrastmaterial 40 may include, may be, and/or may function as a proppant 48for fractures, such as fracture 30 of FIG. 1.

In general, electromagnetic contrast material 40 may include anysuitable material that may provide, or that may exhibit, electromagneticcontrast relative to naturally occurring strata that may be present, orthat naturally may be present, within subsurface region 12 and/orproximate wellbore 20. This electromagnetic contrast may include anysuitable difference in electrical conductivity, difference inpermittivity, difference in reflectivity, difference in absorptivity,and/or difference in scattering properties for the electromagnetic probesignal relative, or compared, to the naturally occurring strata.

Electromagnetic contrast material 40 may have and/or define any suitablesize and/or shape. As an example, and as illustrated in FIG. 2,electromagnetic contrast material 40 may include and/or be a pluralityof round, a plurality of spherical, and/or a plurality of at leastsubstantially spherical particles. Additionally or alternatively, and asillustrated in FIG. 3, electromagnetic contrast material 40 may includeand/or be a plurality of cylindrical, or rod-shaped, particles. In someexamples, and as discussed, electromagnetic contrast material 40 mayfunction as, may be, and/or may be sized to be a proppant. In someexamples, electromagnetic contrast material 40 may be sized to bepositioned and/or to flow, within an interstitial space of a proppantmaterial that props fracture 30.

As discussed herein, electromagnetic contrast material 40 may include anelectrically conductive material 42, such as a metal and/or anelectrically conductive particle. Such electromagnetic contrast material40 may be defined by the electrically conductive material, may be fullydefined by the electrically conductive material, may consist of theelectrically conductive material, and/or may consist essentially of theelectrically conductive material.

In some examples, electrically conductive material 42 may form and/ordefine an electrically conductive coating 44 that may coat and/or covera remainder of the electromagnetic contrast material. In some examples,electrically conductive material 42 may form and/or define anelectrically conductive core 46 of the electromagnetic contrastmaterial.

FIG. 4 is a flowchart depicting examples of methods 100 of monitoring amorphology of a fracture that extends from a wellbore of a hydrocarbonwell, according to the present disclosure. Methods 100 may includeselecting an electromagnetic contrast material at 105, providing theelectromagnetic contrast material to the wellbore at 110, pressurizing acasing conduit at 115, and/or perforating a casing string at 120.Methods 100 include flowing the electromagnetic contrast material at 125and also may include propping a fracture at 130. Methods 100 alsoinclude generating an electromagnetic probe signal at 135, modifying theelectromagnetic probe signal at 140, receiving an electromagneticresultant signal at 145, and determining a morphology of the fracture at150. Methods 100 also may include operatively translating a downholeelectromagnetic transmitter at 155, operatively translating a downholeelectromagnetic receiver at 160, transmitting a data stream at 165,regulating a property of a fracture operation at 170, and/or repeatingat least a portion of the methods at 175.

Selecting the electromagnetic contrast material at 105 may includeselecting the electromagnetic contrast material, or at least oneproperty of the electromagnetic contrast material, in any suitablemanner and/or based upon any suitable criteria. As an example, theselecting at 105 may include selecting such that the electromagneticcontrast material exhibits electromagnetic contrast relative tonaturally occurring strata that may be present, or that naturally may bepresent, within the subsurface region and/or proximate the wellbore. Asanother example, the selecting at 105 may include selecting aconcentration, or a local concentration, for the electromagneticcontrast material, within the subsurface region and/or within thefracture, that is greater than a concentration of a naturally occurringmaterial, which naturally may be present within the subsurface region,that exhibits electromagnetic contrast similar to that of theelectromagnetic contrast material.

As more specific examples, the selecting at 105 may include selectingsuch that the electromagnetic contrast material exhibits a differentelectrical conductivity, a different permittivity, a differentreflectivity, a different absorptivity, and/or different scatteringproperties for the electromagnetic probe signal relative to, or whencompared to, the naturally occurring strata. Examples of theelectromagnetic contrast material are disclosed herein with reference toelectromagnetic contrast material 40 of FIGS. 1-3.

Providing the electromagnetic contrast material to the wellbore at 110may include positioning, or selectively positioning, the electromagneticcontrast material in and/or within the wellbore, such as to permitand/or to facilitate the flowing at 125. In some examples, the providingat 110 may be performed continuously.

In other examples, the providing at 110 may include selectivelyproviding the electromagnetic contrast material to the wellbore basedupon and/or responsive to a supply criteria. In these examples, acarrier fluid initially may be provided to the wellbore without theelectromagnetic contrast material being contained and/or entrainedtherein. As an example, the carrier fluid may be provided to thewellbore to clean the wellbore and/or to permit and/or facilitate thepressurizing at 115. Upon satisfaction of the supply criteria, theproviding at 110 may be performed, such as to also provide theelectromagnetic contrast material to the wellbore. Examples of thesupply criteria include initiation of a fracture, or of a fractureevent, within the subsurface region, establishing at least a thresholdpressure within the wellbore, and/or an initiation of the providing at110 by an operator of the hydrocarbon well.

In some examples, the providing at 110 may include providing theelectromagnetic contrast material in and/or within the carrier fluid. Inthese examples, the electromagnetic contrast material may be dissolved,dispersed, and/or entrained within the carrier fluid. Also in theseexamples, the providing at 110 may include modifying a property, or anelectromagnetic property, of the carrier fluid, such as to alter theelectromagnetic resultant signal. As examples, modification of a densityand/or a viscosity of the carrier fluid may produce, generate, and/orcause changes in the resultant signal that may be generated during themodifying at 140 and/or that may be received during the receiving at145. As another example, and when the carrier fluid includes themagnetorheological fluid, variations in a field strength of theelectromagnetic probe signal may be utilized to produce and/or generatevariations in the rheology of the carrier fluid.

In some examples, a casing string that defines a casing conduit mayextend within the wellbore. In these examples, methods 100 may includepressurizing the casing conduit at 115. The pressurizing at 115 mayinclude pressurizing the casing conduit with and/or utilizing thecarrier fluid. When methods 100 include the pressurizing at 115, thecarrier fluid also may be referred to herein as and/or may include afracture fluid. The pressurizing at 115 may include flowing the carrierfluid, with and/or without electromagnetic contrast material containedtherein, from a surface region and/or into the casing conduit. Duringthe pressurizing at 115, the casing conduit may be sealed, or at leastsubstantially sealed, to prevent fluid flow of the carrier fluidtherefrom, thereby permitting and/or facilitating the pressurizing at115.

When methods 100 include the pressurizing at 115, methods 100 also mayinclude perforating the casing string at 120. The perforating at 120 maybe performed subsequent to the pressurizing at 115; and, responsiveand/or subsequent to the perforating at 120, the fracture may be formedwithin the subsurface region. Stated another way, methods 100 mayinclude forming the fracture, with the forming being responsive toand/or a result of the perforating at 120 and/or a combination of thepressurizing at 115 and the perforating at 120.

Flowing the electromagnetic contrast material at 125 may include flowingthe electromagnetic contrast material into the fracture. Theelectromagnetic contrast material may be entrained within the carrierfluid, when present, which also may flow into the fracture during theflowing at 125, and the flowing at 125 may include flowing theelectromagnetic contrast material, and the carrier fluid, into thefracture. This may include flowing the electromagnetic contrast materialand/or the carrier fluid from the surface region, within the wellbore,to the fracture, and/or into the fracture.

When methods 100 include the perforating at 120, the flowing at 125 maybe responsive to, or a result of, the perforating at 120. Stated anotherway, the flowing at 125 may include flowing the electromagnetic contrastmaterial from the casing conduit and into the fracture via one or moreperforations, within the casing string, that may be formed during theperforating at 120. Stated yet another way, and as discussed, theelectromagnetic contrast material may be contained and/or entrainedwithin the fracture fluid, and the flowing at 125 may include flowingthe electromagnetic contrast material into the fracture with and/orwithin the fracture fluid.

Propping the fracture at 130 may include supporting the fracture and/ormaintaining the fracture in any suitable manner. As an example, theelectromagnetic contrast material may include, may be, and/or may form aportion of a proppant. In this example, the propping at 130 may includepropping the fracture with, via, and/or utilizing the electromagneticcontrast material. As another example, a separate proppant, which isdistinct from the electromagnetic contrast material, may be provided tothe fracture, and the propping at 130 may include propping with theseparate proppant. In some examples, the separate proppant, whenutilized, may be provided to the fracture with the electromagneticcontrast material, with the carrier fluid, during the flowing at 125,and/or at least partially concurrent with the flowing at 125. In someexamples, the separate proppant may be provided to the fracture priorand/or subsequent to the flowing at 125.

Generating the electromagnetic probe signal at 135 may includegenerating the electromagnetic probe signal with the downholeelectromagnetic transmitter. The downhole electromagnetic transmittermay be positioned within the wellbore and/or the generating at 135 mayinclude generating such that the electromagnetic probe signal isincident upon the electromagnetic contrast material.

Modifying the electromagnetic probe signal at 140 may include modifyingthe electromagnetic probe signal with the electromagnetic contrastmaterial and/or responsive to the electromagnetic probe signal beingincident upon the electromagnetic contrast material. Additionally oralternatively, the modifying at 140 may include modifying to produceand/or to generate the electromagnetic resultant signal and/or such thatthe electromagnetic resultant signal is emitted from and/or by theelectromagnetic contrast material.

Receiving the electromagnetic resultant signal at 145 may includereceiving the electromagnetic resultant signal with the downholeelectromagnetic receiver. The downhole electromagnetic receiver may bepositioned within the wellbore and/or the modifying at 140 may includemodifying such that the electromagnetic resultant signal is incidentupon the downhole electromagnetic receiver.

Determining the morphology of the fracture at 150 may includedetermining, establishing, estimating, and/or calculating the morphologyof the fracture based, at least in part, on the electromagneticresultant signal and/or on receipt of the electromagnetic resultantsignal by the downhole electromagnetic receiver.

Operatively translating the downhole electromagnetic transmitter at 155may include operatively translating the downhole electromagnetictransmitter within the subsurface region and/or along a length of thewellbore. Similarly, operatively translating the downholeelectromagnetic receiver at 160 may include operatively translating thedownhole electromagnetic receiver within the subsurface region and/oralong the length of the wellbore. The operatively translating at 155 andthe operatively translating at 160 are discussed in more detail herein.

In some examples, methods 100 further may include transmitting the datastream at 165. The transmitting at 165 may include transmitting anysuitable data stream to the surface region. The data stream may beindicative of the morphology of the fracture, may be based upon theelectromagnetic probe signal, may be based upon the electromagneticresultant signal, and/or may be based upon a comparison between theelectromagnetic probe signal and the electromagnetic resultant signal.

The transmitting at 165 may be performed in any suitable manner As anexample, a data transmission structure, such as data transmissionstructure 70 of FIG. 1, may extend within the wellbore, may extendbetween the downhole electromagnetic receiver and the surface region,and/or may be utilized to convey the data signal between the downholeelectromagnetic receiver and the surface region. As a more specificexample, an electrical conductor and/or an optical fiber, such aselectrical conductor and/or optical fiber 74 of FIG. 1, may extendwithin the wellbore and/or between the downhole electromagnetic receiverand the surface region. In this example, the transmitting at 165 mayinclude transmitting with, via, and/or utilizing the electricalconductor and/or the optical fiber. As another more specific example,the transmitting at 165 may include wirelessly transmitting the datastream. In this example, the wirelessly transmitting may utilize adownhole wireless communication network, such as downhole wirelesscommunication network 76 of FIG. 1.

As discussed, methods 100 may include the pressurizing at 115 and theperforating at 120. As also discussed, the fracture may be formedresponsive to and/or as a result of the pressurizing at 115, theperforating at 120, or a combination of the pressurizing at 115 and theperforating at 120. Formation of the fracture may be referred to hereinas a fracture operation, which may include the pressurizing at 115and/or the perforating at 120. Stated another way, methods 100 mayinclude performing the fracture operation.

When methods 100 include performing the fracture operation, methods 100also may include regulating the property of the fracture operation at170. The regulating at 170 may include regulating any suitable propertyand/or parameter of the fracture operation and may be based, at least inpart, on the determining at 150. As an example, the determining at 150may be utilized to determine, to establish, and/or to quantify an extentof the fracture. In this example, the regulating at 170 may includeregulating a flow rate of the carrier fluid, a pressure of the carrierfluid, and/or a total volume of the carrier fluid that is provided tothe casing conduit and/or that flows into the fracture based, at leastin part, on the extent of the fracture as determined during thedetermining at 150. As another example, the regulating at 170 mayinclude ceasing supply of the carrier fluid to the casing conduit and/orceasing formation of the fracture responsive to the determining at 150indicating that the fracture has reached at least a threshold fracturesize and/or extent within the subsurface region.

Repeating at least the portion of the methods at 175 may includerepeating any suitable portion of methods 100 in any suitable order. Asan example, the repeating at 175 may include repeating the generating at135, the modifying at 140, the receiving at 145, and the determining at150 at a plurality of different times to increase measurement resolutionregarding the morphology of the fracture, to determine the morphology ofthe fracture at the plurality of different times, and/or to generateinformation regarding the morphology of the fracture as a function oftime.

As another example, the repeating at 175 may include repeatedlyperforming the operatively translating at 155 and the operativelytranslating at 160 to position the downhole electromagnetic transmitterand the downhole electromagnetic receiver in different regions of thewellbore. In this example, the repeating at 175 further may includerepeating the generating at 135, the modifying at 140, the receiving at145, and the determining at 150 within each region of the wellbore, suchas to determine the morphology of the fracture within, or adjacent to,each region of the wellbore and/or to generate information regarding themorphology of the fracture, or the morphology of a plurality of distinctfractures, as a function of location, or position, within the subsurfaceregion. Additional and/or more specific examples of the repeating at 175are disclosed herein.

In some examples, and as discussed in more detail herein with referenceto FIG. 1, methods 100 may be performed within a hydrocarbon well thatincludes a first wellbore, such as wellbore 21 of FIG. 1, and a secondwellbore, such as wellbore 22 of FIG. 1. In these examples, the downholeelectromagnetic transmitter may be positioned within a transmittingwellbore, which includes one of the first wellbore and the secondwellbore, and the downhole electromagnetic receiver may be positionedwithin a receiving wellbore, which includes the other of the firstwellbore and the second wellbore. Stated another way, and in theseexamples, the generating at 135 may include generating within the firstwellbore and/or within the transmitting wellbore, and the receiving at145 may include receiving within the second wellbore and/or within thereceiving wellbore. In these examples, the modifying at 140 may includemodifying a phase, an amplitude, and/or a frequency of theelectromagnetic probe signal via interaction with the electromagneticcontrast material and/or to produce and/or generate the electromagneticresultant signal.

In these examples, the operatively translating at 155, when performed,may include operatively translating the downhole electromagnetictransmitter in, within, and/or along the length of the transmittingwellbore. Similarly, the operatively translating at 160, when performed,may include operatively translating the downhole electromagneticreceiver in, within, and/or along the length of the receiving wellbore.The operatively translating at 155 and the operatively translating at160 may be performed concurrently, or at least substantiallyconcurrently.

In these examples, the operatively translating at 155 and theoperatively translating at 160 may include maintaining the downholeelectromagnetic transmitter and the downhole electromagnetic receiverequidistant, or at least substantially equidistant, from the surfaceregion. Additionally or alternatively, the operatively translating at155 and the operatively translating at 160 may include operativelytranslating the downhole electromagnetic transmitter and the downholeelectromagnetic receiver at the same, or at least substantially thesame, translation rate. Additionally or alternatively, the operativelytranslating at 155 and the operatively translating at 160 may includeoperatively translating the downhole electromagnetic transmitter and thedownhole electromagnetic receiver in the same, or in at leastsubstantially the same direction. Stated another way, the operativelytranslating at 155 and the operatively translating at 160 may beperformed such that the downhole electromagnetic transmitter and thedownhole electromagnetic receiver remain parallel, or at leastsubstantially parallel, to one other within the subsurface region and/orsuch that a distance between the downhole electromagnetic transmitterand the downhole electromagnetic receiver is constant, or at leastsubstantially constant.

In these examples, methods 100 may include repeatedly performing, suchas during the repeating at 175, the generating at 135, the modifying at140, the receiving at 145, and the determining at 150 during theoperatively translating at 155 and also during the operativelytranslating at 160. This may permit and/or facilitate determination ofthe morphology of the fracture as a function of location and/or at aplurality of spaced-apart locations along the length of the transmittingwellbore.

In these examples, and because the downhole electromagnetic transmitteris positioned within the transmitting wellbore and the downholeelectromagnetic receiver is positioned within the receiving wellbore,the determining at 150 may include determining the morphology of thefracture within a plane, such as plane 54 of FIG. 1, that extendsbetween the transmitting wellbore and the receiving wellbore and/or thatextends between the downhole electromagnetic transmitter and thedownhole electromagnetic receiver. This may be referred to herein asgeneration of a plane array that shows fracture morphology within theplane.

In some examples, and as discussed in more detail herein with referenceto FIG. 1, methods 100 may be performed within a hydrocarbon well thatincludes a single wellbore and/or may be performed with theelectromagnetic transmitter and the electromagnetic receiver bothpositioned within the wellbore, or within the single wellbore. In theseexamples, the generating at 135 may include transmitting theelectromagnetic probe signal from, or away from, the wellbore, and thereceiving at 145 may include receiving the electromagnetic resultantsignal within the wellbore. In these examples, the modifying at 140 mayinclude reflecting and/or scattering at least a portion of theelectromagnetic probe signal toward the wellbore as the electromagneticresultant signal.

In these examples, the operatively translating at 155, when performed,may include operatively translating the downhole electromagnetictransmitter in, within, and/or along the length of the wellbore, or thesingle wellbore. Similarly, the operatively translating at 160, whenperformed, may include operatively translating the downholeelectromagnetic receiver in, within, and/or along the length of thewellbore of the single wellbore. This may include maintaining a fixed,or an at least substantially fixed, relative orientation, or distance,between the downhole electromagnetic transmitter and the downholeelectromagnetic receiver during the operatively translating at 155 andduring the operatively translating at 160. As an example, the downholeelectromagnetic transmitter and the downhole electromagnetic receivermay be operatively attached to one another and/or may be configured totranslate as a unit during the operatively translating at 155 and duringthe operatively translating at 160.

In these examples, methods 100 may include repeatedly performing, suchas during the repeating at 175, the generating at 135, the modifying at140, the receiving at 145, and the determining at 150 during theoperatively translating at 155 and also during the operativelytranslating at 160. This may permit and/or facilitate determination ofthe morphology of the fracture as a function of location and/or at aplurality of spaced-apart locations along the length of the wellbore, orof the single wellbore.

In these examples, the determining at 150 may include determining anaverage depth of penetration of the electromagnetic probe signal and/oran average fracture extent, or distance, from the wellbore as a functionof position, or location, along the length of the wellbore. Additionallyor alternatively, the determining at 150 may include determining afracture height along, or as measured along, the length of the wellboreand/or determining a concentration of electromagnetic contrast materialas a function of position, or location, along the length of thewellbore.

-   -   Hydrocarbon wells 18 and/or methods 100, which are disclosed        herein, may be utilized with a variety of different processes        and/or operations. In some examples, the repeating at 175 may        include repeatedly performing at least the flowing at 125, the        generating at 135, the modifying at 140, the receiving at 145,        and the determining at 150 during a monitoring timeframe.

In one such example, the carrier fluid may include and/or be a drillingmud for a drilling operation of the hydrocarbon well. In this example,the repeating at 175 may include repeating to monitor for, or to detect,lost returns due to fracture formation during the drilling operation.

In another such example, the carrier fluid may include and/or be acuttings re-injection fluid that includes drill cuttings and that isutilized as part of a cuttings re-injection operation. In this example,methods 100 may include forming the fracture via flow of the cuttingsre-injection fluid onto the subsurface region, and the repeating at 175may include repeating to measure and/or monitor fracture growth duringthe cuttings re-injection operation.

In another such example, the carrier fluid may include produced waterthat may be utilized as part of a water re-injection operation. In thisexample, methods 100 may include forming the fracture via flow of theproduced water into the subsurface region, and the repeating at 175 mayinclude repeating to measure and/or monitor fracture growth during thewater re-injection operation.

In the present disclosure, several of the illustrative, non-exclusiveexamples have been discussed and/or presented in the context of flowdiagrams, or flow charts, in which the methods are shown and describedas a series of blocks, or steps. Unless specifically set forth in theaccompanying description, it is within the scope of the presentdisclosure that the order of the blocks may vary from the illustratedorder in the flow diagram, including with two or more of the blocks (orsteps) occurring in a different order and/or concurrently.

As used herein, the term “and/or” placed between a first entity and asecond entity means one of (1) the first entity, (2) the second entity,and (3) the first entity and the second entity. Multiple entities listedwith “and/or” should be construed in the same manner, i.e., “one ormore” of the entities so conjoined. Other entities may optionally bepresent other than the entities specifically identified by the “and/or”clause, whether related or unrelated to those entities specificallyidentified. Thus, as a non-limiting example, a reference to “A and/orB,” when used in conjunction with open-ended language such as“comprising” may refer, in one embodiment, to A only (optionallyincluding entities other than B); in another embodiment, to B only(optionally including entities other than A); in yet another embodiment,to both A and B (optionally including other entities). These entitiesmay refer to elements, actions, structures, steps, operations, values,and the like.

As used herein, the phrase “at least one,” in reference to a list of oneor more entities should be understood to mean at least one entityselected from any one or more of the entities in the list of entities,but not necessarily including at least one of each and every entityspecifically listed within the list of entities and not excluding anycombinations of entities in the list of entities. This definition alsoallows that entities may optionally be present other than the entitiesspecifically identified within the list of entities to which the phrase“at least one” refers, whether related or unrelated to those entitiesspecifically identified. Thus, as a non-limiting example, “at least oneof A and B” (or, equivalently, “at least one of A or B,” or,equivalently “at least one of A and/or B”) may refer, in one embodiment,to at least one, optionally including more than one, A, with no Bpresent (and optionally including entities other than B); in anotherembodiment, to at least one, optionally including more than one, B, withno A present (and optionally including entities other than A); in yetanother embodiment, to at least one, optionally including more than one,A, and at least one, optionally including more than one, B (andoptionally including other entities). In other words, the phrases “atleast one,” “one or more,” and “and/or” are open-ended expressions thatare both conjunctive and disjunctive in operation. For example, each ofthe expressions “at least one of A, B, and C,” “at least one of A, B, orC,” “one or more of A, B, and C,” “one or more of A, B, or C,” and “A,B, and/or C” may mean A alone, B alone, C alone, A and B together, A andC together, B and C together, A, B, and C together, and optionally anyof the above in combination with at least one other entity.

In the event that any patents, patent applications, or other referencesare incorporated by reference herein and (1) define a term in a mannerthat is inconsistent with and/or (2) are otherwise inconsistent with,either the non-incorporated portion of the present disclosure or any ofthe other incorporated references, the non-incorporated portion of thepresent disclosure shall control, and the term or incorporateddisclosure therein shall only control with respect to the reference inwhich the term is defined and/or the incorporated disclosure was presentoriginally.

As used herein, the terms “adapted” and “configured” mean that theelement, component, or other subject matter is designed and/or intendedto perform a given function. Thus, the use of the terms “adapted” and“configured” should not be construed to mean that a given element,component, or other subject matter is simply “capable of” performing agiven function but that the element, component, and/or other subjectmatter is specifically selected, created, implemented, utilized,programmed, and/or designed for the purpose of performing the function.It is also within the scope of the present disclosure that elements,components, and/or other recited subject matter that is recited as beingadapted to perform a particular function may additionally oralternatively be described as being configured to perform that function,and vice versa.

As used herein, the phrase, “for example,” the phrase, “as an example,”and/or simply the term “example,” when used with reference to one ormore components, features, details, structures, embodiments, and/ormethods according to the present disclosure, are intended to convey thatthe described component, feature, detail, structure, embodiment, and/ormethod is an illustrative, non-exclusive example of components,features, details, structures, embodiments, and/or methods according tothe present disclosure. Thus, the described component, feature, detail,structure, embodiment, and/or method is not intended to be limiting,required, or exclusive/exhaustive; and other components, features,details, structures, embodiments, and/or methods, including structurallyand/or functionally similar and/or equivalent components, features,details, structures, embodiments, and/or methods, are also within thescope of the present disclosure.

As used herein, “at least substantially,” when modifying a degree orrelationship, may include not only the recited “substantial” degree orrelationship, but also the full extent of the recited degree orrelationship. A substantial amount of a recited degree or relationshipmay include at least 75% of the recited degree or relationship. Forexample, an object that is at least substantially formed from a materialincludes objects for which at least 75% of the objects are formed fromthe material and also includes objects that are completely formed fromthe material. As another example, a first length that is at leastsubstantially as long as a second length includes first lengths that arewithin 75% of the second length and also includes first lengths that areas long as the second length.

INDUSTRIAL APPLICABILITY

The systems and methods disclosed herein are applicable to thehydrocarbon well drilling and completion industries.

It is believed that the disclosure set forth above encompasses multipledistinct inventions with independent utility. While each of theseinventions has been disclosed in its preferred form, the specificembodiments thereof as disclosed and illustrated herein are not to beconsidered in a limiting sense as numerous variations are possible. Thesubject matter of the inventions includes all novel and non-obviouscombinations and subcombinations of the various elements, features,functions, and/or properties disclosed herein. Similarly, where theclaims recite “a” or “a first” element or the equivalent thereof, suchclaims should be understood to include incorporation of one or more suchelements, neither requiring nor excluding two or more such elements.

It is believed that the following claims particularly point out certaincombinations and subcombinations that are directed to one of thedisclosed inventions and are novel and non-obvious. Inventions embodiedin other combinations and subcombinations of features, functions,elements, and/or properties may be claimed through amendment of thepresent claims or presentation of new claims in this or a relatedapplication. Such amended or new claims, whether they are directed to adifferent invention or directed to the same invention, whetherdifferent, broader, narrower, or equal in scope to the original claims,are also regarded as included within the subject matter of theinventions of the present disclosure.

What is claimed is:
 1. A method of monitoring a morphology of a fracture that extends from a wellbore of a hydrocarbon well and within a subsurface region, the method comprising: flowing an electromagnetic contrast material from the wellbore and into the fracture; generating an electromagnetic probe signal with a downhole electromagnetic transmitter such that the electromagnetic probe signal is incident upon the electromagnetic contrast material; modifying the electromagnetic probe signal, with the electromagnetic contrast material, to generate an electromagnetic resultant signal; receiving the electromagnetic resultant signal with a downhole electromagnetic receiver; and determining the morphology of the fracture based, at least in part, on the electromagnetic resultant signal.
 2. The method of claim 1, wherein the wellbore is a first wellbore, wherein the downhole electromagnetic transmitter is positioned within a transmitting wellbore that includes one of the first wellbore and a second wellbore, and further wherein the downhole electromagnetic receiver is positioned within a receiving wellbore that includes the other of the first wellbore and the second wellbore, wherein the generating includes generating within the first wellbore, and further wherein the receiving includes receiving within the second wellbore.
 3. The method of claim 2, wherein the method further includes operatively translating the downhole electromagnetic transmitter along a length of the transmitting wellbore and concurrently operatively translating the downhole electromagnetic receiver along a length of the receiving wellbore, wherein the operatively translating the downhole electromagnetic transmitter and the concurrently operatively translating the downhole electromagnetic receiver includes at least one of: (i) maintaining the downhole electromagnetic transmitter and the downhole electromagnetic receiver at least substantially equidistant from a surface region; (ii) operatively translating the downhole electromagnetic transmitter and the downhole electromagnetic receiver at substantially the same translation rate; and (iii) operatively translating the downhole electromagnetic transmitter and the downhole electromagnetic receiver in substantially the same direction.
 4. The method of claim 3, wherein, during the operatively translating the downhole electromagnetic transmitter and the concurrently operatively translating the downhole electromagnetic receiver, the method further includes repeatedly performing the generating, the modifying, the receiving, and the determining to determine the morphology of the fracture at a plurality of spaced-apart locations along the length of the transmitting wellbore.
 5. The method of claim 2, wherein the modifying the electromagnetic probe signal includes at least one of: (i) modifying a phase of the electromagnetic probe signal to generate the to electromagnetic resultant signal; (ii) modifying an amplitude of the electromagnetic probe signal to generate the electromagnetic resultant signal; and (iii) modifying a frequency of the electromagnetic probe signal to generate the electromagnetic resultant signal.
 6. The method of claim 2, wherein the determining includes determining the fracture morphology within a plane that extends between the first wellbore and the second wellbore.
 7. The method of claim 2, wherein the electromagnetic contrast material includes an electrically conductive material.
 8. The method of claim 1, wherein the downhole electromagnetic transmitter and the downhole electromagnetic receiver both are positioned within the wellbore, wherein the generating includes at least one of: (i) transmitting the electromagnetic probe signal from the wellbore; and (ii) transmitting the electromagnetic probe signal away from the wellbore; and further wherein the receiving includes receiving within the wellbore.
 9. The method of claim 8, wherein the method further includes operatively translating the downhole electromagnetic transmitter and the downhole electromagnetic receiver along the length of the wellbore, and maintaining an at least substantially fixed relative orientation between the downhole electromagnetic transmitter and the downhole electromagnetic receiver during the operatively translating.
 10. The method of claim 9, wherein, during the operatively translating, the method further includes repeatedly performing the generating, the modifying, the receiving, and the determining to determine the morphology of the fracture at a plurality of spaced-apart locations along a length of the wellbore.
 11. The method of claim 8, wherein the determining includes determining at least one of: (i) an average depth of penetration of the electromagnetic probe signal as a function of position along the length of the wellbore; (ii) an average fracture extent, from the wellbore, as a function of position along the length of the wellbore; (iii) a fracture height as measured along the length of the wellbore; and (iv) a concentration of electromagnetic contrast material as a function of position along the length of the wellbore.
 12. The method of claim 1, wherein the modifying includes at least one of: (i) reflecting at least a portion of the electromagnetic probe signal toward the wellbore as the electromagnetic resultant signal; and (ii) scattering at least a portion of the electromagnetic probe signal toward the wellbore as the electromagnetic resultant signal.
 13. The method of claim 1, wherein the electromagnetic contrast material includes at least one of: (i) an electromagnetically shielding material; (ii) an electromagnetically shielding liquid; (iii) an electromagnetically shielding particulate; (iv) a material that scatters electromagnetic radiation; (v) a liquid that scatters electromagnetic radiation; and (vi) a particulate that scatters electromagnetic radiation.
 14. The method of claim 1, wherein the method further includes selecting the electromagnetic contrast material such that the electromagnetic contrast material exhibits electromagnetic contrast relative to naturally occurring strata present within the subsurface region.
 15. The method of claim 1, wherein the flowing the electromagnetic contrast material includes flowing the electromagnetic contrast material within a carrier fluid.
 16. The method of claim 15, wherein a casing string that defines a casing conduit extends within the wellbore, wherein the carrier fluid includes a fracture fluid, and further wherein the method includes: (i) pressurizing the casing conduit with the fracture fluid; and (ii) subsequent to the pressurizing, perforating the casing conduit to form the fracture.
 17. The method of claim 16, wherein the flowing is responsive to the perforating.
 18. The method of claim 15, wherein the method further includes modifying an electromagnetic property of the carrier fluid to alter the electromagnetic resultant signal.
 19. The method of claim 1, wherein the generating the electromagnetic probe signal includes generating at a probe signal frequency of at least 10 MHz and at most 2.5 GHz.
 20. A hydrocarbon well, comprising: a wellbore that extends within a subsurface region; a fracture that extends from the wellbore and within the subsurface region; an electromagnetic contrast material positioned within the fracture; a downhole electromagnetic transmitter configured to direct an electromagnetic probe signal incident upon the electromagnetic contrast material; and a downhole electromagnetic receiver configured to receive an electromagnetic resultant signal from the electromagnetic contrast material.
 21. The hydrocarbon well of claim 20, wherein the wellbore is a first wellbore, wherein the hydrocarbon well further includes a second wellbore, wherein the downhole electromagnetic transmitter is positioned within one of the first wellbore and the second wellbore, and further wherein the downhole electromagnetic receiver is positioned within the other of the first wellbore and the second wellbore.
 22. The hydrocarbon well of claim 20, wherein the electromagnetic contrast material includes an electrically conductive material.
 23. The hydrocarbon well of claim 20, wherein the downhole electromagnetic transmitter and the downhole electromagnetic receiver both are positioned within the wellbore.
 24. The hydrocarbon well of claim 23, wherein the electromagnetic contrast material includes at least one of: (i) an electromagnetically shielding material; (ii) an electromagnetically shielding liquid; (iii) an electromagnetically shielding particulate; (iv) a material that scatters electromagnetic radiation; (v) a liquid that scatters electromagnetic radiation; and (vi) a particulate that scatters electromagnetic radiation.
 25. The hydrocarbon well of claim 20, wherein the electromagnetic contrast material exhibits electromagnetic contrast relative to naturally occurring strata present within the subsurface region. 